WO2009146158A1

WO2009146158A1 - Using mines and tunnels for treating subsurface hydrocarbon containing formations

Info

Publication number: WO2009146158A1
Application number: PCT/US2009/040139
Authority: WO
Inventors: David Booth Burns; Horng Jye Hwang; Jochen Marwede; Duncan Charles Mcdonald; Robert George Prince-Wright
Original assignee: Shell Oil Company; Shell Internationale Research Maatschappij B.V.
Priority date: 2008-04-18
Filing date: 2009-04-10
Publication date: 2009-12-03
Also published as: CN102007266B; US8562078B2; JP2012503111A; AU2009251533A1; EA019751B1; EP2262978A1; US8636323B2; IL208162A0; IL208162A; CN102007266A; US9528322B2; CA2718767C; US20090272533A1; US8172335B2; US20090272578A1; US8162405B2; AU2009251533B2; US20090260824A1; EA201001670A1; US20100071904A1

Abstract

A system for treating a subsurface hydrocarbon containing formation is disclosed. The system includes one or more tunnels. The tunnels have an average diameter of at least 1 m. At least one tunnel is connected to the surface. Two or more wellbores extend from at least one of the tunnels into at least a portion of the subsurface hydrocarbon containing formation. At least two of the wellbores contain elongated heat sources configured to heat at least a portion of the subsurface hydrocarbon containing formation such that at least some hydrocarbons are mobilized.

Description

USING MINES AND TUNNELS FOR TREATING SUBSURFACE HYDROCARBON

CONTAINING FORMATIONS

BACKGROUND 1. Field of the Invention

[0001] The present invention relates generally to methods and systems for production of hydrocarbons, hydrogen, and/or other products from various subsurface formations such as hydrocarbon containing formations.

2. Description of Related Art

[0002] Hydrocarbons obtained from subterranean formations are often used as energy resources, as feedstocks, and as consumer products. Concerns over depletion of available hydrocarbon resources and concerns over declining overall quality of produced hydrocarbons have led to development of processes for more efficient recovery, processing and/or use of available hydrocarbon resources. In situ processes may be used to remove hydrocarbon materials from subterranean formations. Chemical and/or physical properties of hydrocarbon material in a subterranean formation may need to be changed to allow hydrocarbon material to be more easily removed from the subterranean formation. The chemical and physical changes may include in situ reactions that produce removable fluids, composition changes, solubility changes, density changes, phase changes, and/or viscosity changes of the hydrocarbon material in the formation. A fluid may be, but is not limited to, a gas, a liquid, an emulsion, a slurry, and/or a stream of solid particles that has flow characteristics similar to liquid flow. [0003] Heaters may be placed in wellbores to heat a formation during an in situ process. Examples of in situ processes utilizing downhole heaters are illustrated in U.S. Patent Nos. 2,634,961 to Ljungstrom; 2,732,195 to Ljungstrom; 2,780,450 to Ljungstrom; 2,789,805 to Ljungstrom; 2,923,535 to Ljungstrom; and 4,886,118 to Van Meurs et al. [0004] Many different types of wells or wellbores may be used to treat the hydrocarbon containing formation using an in situ heat treatment process. In some embodiments, vertical and/or substantially vertical wells are used to treat the formation. In some embodiments, horizontal or substantially horizontal wells (such as J-shaped wells and/or L- shaped wells), and/or u-shaped wells are used to treat the formation. In some embodiments, combinations of horizontal wells, vertical wells, and/or other combinations are used to treat the formation. In certain embodiments, wells extend through the overburden of the formation to a hydrocarbon containing layer of the formation. In some situations, heat in the wells is lost to the overburden. In some situations, surface and overburden infrastructures used to support heaters and/or production equipment in horizontal wellbores or u-shaped wellbores are large in size and/or numerous.

[0005] There has been a significant amount of effort to develop methods and systems to economically produce hydrocarbons, hydrogen, and/or other products from hydrocarbon containing formations. At present, however, there are still many hydrocarbon containing formations from which hydrocarbons, hydrogen, and/or other products cannot be economically produced. Thus, there is a need for improved methods and systems that enable smaller sized heaters and/or smaller sized equipment to be used to treat the formation. There is also a need for improved methods and systems that reduce energy costs for treating the formation, reduce emissions from the treatment process, facilitate heating system installation, and/or reduce heat loss to the overburden as compared to hydrocarbon recovery processes that utilize surface based equipment.

SUMMARY

[0006] Embodiments described herein generally relate to systems, methods, and heaters for treating a subsurface formation. [0007] In certain embodiments, the invention provides one or more systems, methods, and/or heaters. In some embodiments, the systems, methods, and/or heaters are used for treating a subsurface formation.

[0008] In certain embodiments, the invention provides a system for treating a subsurface hydrocarbon containing formation, comprising: one or more tunnels, the tunnels having an average diameter of at least 1 m, at least one tunnel being connected to the surface; and two or more wellbores extending from at least one of the tunnels into at least a portion of the subsurface hydrocarbon containing formation, at least two of the wellbores containing elongated heat sources configured to heat at least a portion of the subsurface hydrocarbon containing formation such that at least some hydrocarbons are mobilized. [0009] In certain embodiments, the invention provides a method of treating a subsurface hydrocarbon containing formation, comprising: providing heat from the system to the subsurface hydrocarbon containing formation to mobilize at least some of the hydrocarbons in the formation, the heat being provided by the system. [0010] In further embodiments, features from specific embodiments may be combined with features from other embodiments. For example, features from one embodiment may be combined with features from any of the other embodiments.

[0011] In further embodiments, treating a subsurface formation is performed using any of the methods, systems, or heaters described herein.

[0012] In further embodiments, additional features may be added to the specific embodiments described herein.

BRIEF DESCRIPTION OF THE DRAWINGS [0013] Advantages of the present invention may become apparent to those skilled in the art with the benefit of the following detailed description and upon reference to the accompanying drawings in which:

[0014] FIG. 1 shows a schematic view of an embodiment of a portion of an in situ heat treatment system for treating a hydrocarbon containing formation. [0015] FIG. 2 depicts a perspective view of an embodiment of an underground treatment system.

[0016] FIG. 3 depicts a perspective view of tunnels of an embodiment of an underground treatment system.

[0017] FIG. 4 depicts another exploded perspective view of a portion of an underground treatment system and tunnels.

[0018] FIG. 5 depicts a side view representation of an embodiment for flowing heated fluid through heat sources between tunnels.

[0019] FIG. 6 depicts a top view representation of an embodiment for flowing heated fluid through heat sources between tunnels. [0020] FIG. 7 depicts a perspective view of an embodiment of an underground treatment system having heater wellbores spanning between to two tunnels of the underground treatment system.

[0021] FIG. 8 depicts a top view of an embodiment of tunnels with wellbore chambers.

[0022] FIG. 9 depicts a schematic view of tunnel sections of an embodiment of an underground treatment system.

[0023] FIG. 10 depicts a schematic view of an embodiment of an underground treatment system with surface production.

[0024] FIG. 11 depicts a side view of an embodiment of an underground treatment system. [0025] While the invention is susceptible to various modifications and alternative forms, specific embodiments thereof are shown by way of example in the drawings and may herein be described in detail. The drawings may not be to scale. It should be understood, however, that the drawings and detailed description thereto are not intended to limit the invention to the particular form disclosed, but on the contrary, the intention is to cover all modifications, equivalents and alternatives falling within the spirit and scope of the present invention as defined by the appended claims.

DETAILED DESCRIPTION [0026] The following description generally relates to systems and methods for treating hydrocarbons in the formations. Such formations may be treated to yield hydrocarbon products, hydrogen, and other products.

[0027] "API gravity" refers to API gravity at 15.5 ⁰C (60 ⁰F). API gravity is as determined by ASTM Method D6822 or ASTM Method D1298. [0028] "ASTM" refers to American Standard Testing and Materials.

[0029] "Carbon number" refers to the number of carbon atoms in a molecule. A hydrocarbon fluid may include various hydrocarbons with different carbon numbers. The hydrocarbon fluid may be described by a carbon number distribution. Carbon numbers and/or carbon number distributions may be determined by true boiling point distribution and/or gas-liquid chromatography.

[0030] "Cracking" refers to a process involving decomposition and molecular recombination of organic compounds to produce a greater number of molecules than were initially present. In cracking, a series of reactions take place accompanied by a transfer of hydrogen atoms between molecules. For example, naphtha may undergo a thermal cracking reaction to form ethene and H₂.

[0031] "Fluid pressure" is a pressure generated by a fluid in a formation. "Lithostatic pressure" (sometimes referred to as "lithostatic stress") is a pressure in a formation equal to a weight per unit area of an overlying rock mass. "Hydrostatic pressure" is a pressure in a formation exerted by a column of water. [0032] A "formation" includes one or more hydrocarbon containing layers, one or more non-hydrocarbon layers, an overburden, and/or an underburden. "Hydrocarbon layers" refer to layers in the formation that contain hydrocarbons. The hydrocarbon layers may contain non-hydrocarbon material and hydrocarbon material. The "overburden" and/or the "underburden" include one or more different types of impermeable materials. For example, the overburden and/or underburden may include rock, shale, mudstone, or wet/tight carbonate. In some embodiments of in situ heat treatment processes, the overburden and/or the underburden may include a hydrocarbon containing layer or hydrocarbon containing layers that are relatively impermeable and are not subjected to temperatures during in situ heat treatment processing that result in significant characteristic changes of the hydrocarbon containing layers of the overburden and/or the underburden. For example, the underburden may contain shale or mudstone, but the underburden is not allowed to heat to pyrolysis temperatures during the in situ heat treatment process. In some cases, the overburden and/or the underburden may be somewhat permeable.

[0033] "Formation fluids" refer to fluids present in a formation and may include pyrolyzation fluid, synthesis gas, mobilized hydrocarbons, and water (steam). Formation fluids may include hydrocarbon fluids as well as non-hydrocarbon fluids. The term "mobilized fluid" refers to fluids in a hydrocarbon containing formation that are able to flow as a result of thermal treatment of the formation. "Produced fluids" refer to fluids removed from the formation.

[0034] A "heat source" is any system for providing heat to at least a portion of a formation substantially by conductive and/or radiative heat transfer. For example, a heat source may include electric heaters such as an insulated conductor, an elongated member, and/or a conductor disposed in a conduit. A heat source may also include systems that generate heat by burning a fuel external to or in a formation. The systems may be surface burners, downhole gas burners, flameless distributed combustors, and natural distributed combustors. In some embodiments, heat provided to or generated in one or more heat sources may be supplied by other sources of energy. The other sources of energy may directly heat a formation, or the energy may be applied to a transfer medium that directly or indirectly heats the formation. It is to be understood that one or more heat sources that are applying heat to a formation may use different sources of energy. Thus, for example, for a given formation some heat sources may supply heat from electric resistance heaters, some heat sources may provide heat from combustion, and some heat sources may provide heat from one or more other energy sources (for example, chemical reactions, solar energy, wind energy, biomass, or other sources of renewable energy). A chemical reaction may include an exothermic reaction (for example, an oxidation reaction). A heat source may also include a heater that provides heat to a zone proximate and/or surrounding a heating location such as a heater well.

[0035] A "heater" is any system or heat source for generating heat in a well or a near wellbore region. Heaters may be, but are not limited to, electric heaters, burners, combustors that react with material in or produced from a formation, and/or combinations thereof.

[0036] "Heavy hydrocarbons" are viscous hydrocarbon fluids. Heavy hydrocarbons may include highly viscous hydrocarbon fluids such as heavy oil, tar, and/or asphalt. Heavy hydrocarbons may include carbon and hydrogen, as well as smaller concentrations of sulfur, oxygen, and nitrogen. Additional elements may also be present in heavy hydrocarbons in trace amounts. Heavy hydrocarbons may be classified by API gravity. Heavy hydrocarbons generally have an API gravity below about 20°. Heavy oil, for example, generally has an API gravity of about 10-20°, whereas tar generally has an API gravity below about 10°. The viscosity of heavy hydrocarbons is generally greater than about 100 centipoise at 15 °C. Heavy hydrocarbons may include aromatics or other complex ring hydrocarbons.

[0037] Heavy hydrocarbons may be found in a relatively permeable formation. The relatively permeable formation may include heavy hydrocarbons entrained in, for example, sand or carbonate. "Relatively permeable" is defined, with respect to formations or portions thereof, as an average permeability of 10 millidarcy or more (for example, 10 or 100 millidarcy). "Relatively low permeability" is defined, with respect to formations or portions thereof, as an average permeability of less than about 10 millidarcy. One darcy is equal to about 0.99 square micrometers. An impermeable layer generally has a permeability of less than about 0.1 millidarcy. [0038] Certain types of formations that include heavy hydrocarbons may also include, but are not limited to, natural mineral waxes, or natural asphaltites. "Natural mineral waxes" typically occur in substantially tubular veins that may be several meters wide, several kilometers long, and hundreds of meters deep. "Natural asphaltites" include solid hydrocarbons of an aromatic composition and typically occur in large veins. In situ recovery of hydrocarbons from formations such as natural mineral waxes and natural asphaltites may include melting to form liquid hydrocarbons and/or solution mining of hydrocarbons from the formations. [0039] "Hydrocarbons" are generally defined as molecules formed primarily by carbon and hydrogen atoms. Hydrocarbons may also include other elements such as, but not limited to, halogens, metallic elements, nitrogen, oxygen, and/or sulfur. Hydrocarbons may be, but are not limited to, kerogen, bitumen, pyrobitumen, oils, natural mineral waxes, and asphaltites. Hydrocarbons may be located in or adjacent to mineral matrices in the earth. Matrices may include, but are not limited to, sedimentary rock, sands, silicilytes, carbonates, diatomites, and other porous media. "Hydrocarbon fluids" are fluids that include hydrocarbons. Hydrocarbon fluids may include, entrain, or be entrained in non- hydrocarbon fluids such as hydrogen, nitrogen, carbon monoxide, carbon dioxide, hydrogen sulfide, water, and ammonia.

[0040] An "in situ conversion process" refers to a process of heating a hydrocarbon containing formation from heat sources to raise the temperature of at least a portion of the formation above a pyrolysis temperature so that pyrolyzation fluid is produced in the formation. [0041] An "in situ heat treatment process" refers to a process of heating a hydrocarbon containing formation with heat sources to raise the temperature of at least a portion of the formation above a temperature that results in mobilized fluid, visbreaking, and/or pyrolysis of hydrocarbon containing material so that mobilized fluids, visbroken fluids, and/or pyrolyzation fluids are produced in the formation. [0042] "Insulated conductor" refers to any elongated material that is able to conduct electricity and that is covered, in whole or in part, by an electrically insulating material. [0043] "Pyrolysis" is the breaking of chemical bonds due to the application of heat. For example, pyrolysis may include transforming a compound into one or more other substances by heat alone. Heat may be transferred to a section of the formation to cause pyrolysis.

[0044] "Pyrolyzation fluids" or "pyrolysis products" refers to fluid produced substantially during pyrolysis of hydrocarbons. Fluid produced by pyrolysis reactions may mix with other fluids in a formation. The mixture would be considered pyrolyzation fluid or pyrolyzation product. As used herein, "pyrolysis zone" refers to a volume of a formation (for example, a relatively permeable formation such as a tar sands formation) that is reacted or reacting to form a pyrolyzation fluid.

[0045] "Subsidence" is a downward movement of a portion of a formation relative to an initial elevation of the surface. [0046] "Superposition of heat" refers to providing heat from two or more heat sources to a selected section of a formation such that the temperature of the formation at least at one location between the heat sources is influenced by the heat sources. [0047] "Synthesis gas" is a mixture including hydrogen and carbon monoxide. Additional components of synthesis gas may include water, carbon dioxide, nitrogen, methane, and other gases. Synthesis gas may be generated by a variety of processes and feedstocks. Synthesis gas may be used for synthesizing a wide range of compounds. [0048] "Tar" is a viscous hydrocarbon that generally has a viscosity greater than about 10,000 centipoise at 15 ⁰C. The specific gravity of tar generally is greater than 1.000. Tar may have an API gravity less than 10°.

[0049] A "tar sands formation" is a formation in which hydrocarbons are predominantly present in the form of heavy hydrocarbons and/or tar entrained in a mineral grain framework or other host lithology (for example, sand or carbonate). Examples of tar sands formations include formations such as the Athabasca formation, the Grosmont formation, and the Peace River formation, all three in Alberta, Canada; and the Faja formation in the Orinoco belt in Venezuela.

[0050] "Temperature limited heater" generally refers to a heater that regulates heat output (for example, reduces heat output) above a specified temperature without the use of external controls such as temperature controllers, power regulators, rectifiers, or other devices. Temperature limited heaters may be AC (alternating current) or modulated (for example, "chopped") DC (direct current) powered electrical resistance heaters. [0051] "Thickness" of a layer refers to the thickness of a cross section of the layer, wherein the cross section is normal to a face of the layer. [0052] A "u-shaped wellbore" refers to a wellbore that extends from a first opening in the formation, through at least a portion of the formation, and out through a second opening in the formation. In this context, the wellbore may be only roughly in the shape of a "v" or "u", with the understanding that the "legs" of the "u" do not need to be parallel to each other, or perpendicular to the "bottom" of the "u" for the wellbore to be considered "u- shaped". [0053] "Upgrade" refers to increasing the quality of hydrocarbons. For example, upgrading heavy hydrocarbons may result in an increase in the API gravity of the heavy hydrocarbons. [0054] "Visbreaking" refers to the untangling of molecules in fluid during heat treatment and/or to the breaking of large molecules into smaller molecules during heat treatment, which results in a reduction of the viscosity of the fluid.

[0055] "Viscosity" refers to kinematic viscosity at 40 ⁰C unless otherwise specified. Viscosity is as determined by ASTM Method D445.

[0056] The term "wellbore" refers to a hole in a formation made by drilling or insertion of a conduit into the formation. A wellbore may have a substantially circular cross section, or another cross-sectional shape. As used herein, the terms "well" and "opening," when referring to an opening in the formation may be used interchangeably with the term "wellbore."

[0057] A formation may be treated in various ways to produce many different products. Different stages or processes may be used to treat the formation during an in situ heat treatment process. In some embodiments, one or more sections of the formation are solution mined to remove soluble minerals from the sections. Solution mining minerals may be performed before, during, and/or after the in situ heat treatment process. In some embodiments, the average temperature of one or more sections being solution mined may be maintained below about 120 ⁰C.

[0058] In some embodiments, one or more sections of the formation are heated to remove water from the sections and/or to remove methane and other volatile hydrocarbons from the sections. In some embodiments, the average temperature may be raised from ambient temperature to temperatures below about 220 ⁰C during removal of water and volatile hydrocarbons.

[0059] In some embodiments, one or more sections of the formation are heated to temperatures that allow for movement and/or visbreaking of hydrocarbons in the formation. In some embodiments, the average temperature of one or more sections of the formation are raised to mobilization temperatures of hydrocarbons in the sections (for example, to temperatures ranging from 100 ⁰C to 250 ⁰C, from 120 ⁰C to 240 ⁰C, or from 150 ⁰C to 230 ⁰C). [0060] In some embodiments, one or more sections are heated to temperatures that allow for pyrolysis reactions in the formation. In some embodiments, the average temperature of one or more sections of the formation may be raised to pyrolysis temperatures of hydrocarbons in the sections (for example, temperatures ranging from 230 ⁰C to 900 ⁰C, from 240 ⁰C to 400 ⁰C or from 250 ⁰C to 350 ⁰C). [0061] Heating the hydrocarbon containing formation with a plurality of heat sources may establish thermal gradients around the heat sources that raise the temperature of hydrocarbons in the formation to desired temperatures at desired heating rates. The rate of temperature increase through mobilization temperature range and/or pyrolysis temperature range for desired products may affect the quality and quantity of the formation fluids produced from the hydrocarbon containing formation. Slowly raising the temperature of the formation through the mobilization temperature range and/or pyrolysis temperature range may allow for the production of high quality, high API gravity hydrocarbons from the formation. Slowly raising the temperature of the formation through the mobilization temperature range and/or pyrolysis temperature range may allow for the removal of a large amount of the hydrocarbons present in the formation as hydrocarbon product. [0062] In some in situ heat treatment embodiments, a portion of the formation is heated to a desired temperature instead of slowly heating the temperature through a temperature range. In some embodiments, the desired temperature is 300 ⁰C, 325 ⁰C, or 350 ⁰C. Other temperatures may be selected as the desired temperature.

[0063] Superposition of heat from heat sources allows the desired temperature to be relatively quickly and efficiently established in the formation. Energy input into the formation from the heat sources may be adjusted to maintain the temperature in the formation substantially at a desired temperature. [0064] Mobilization and/or pyrolysis products may be produced from the formation through production wells. In some embodiments, the average temperature of one or more sections is raised to mobilization temperatures and hydrocarbons are produced from the production wells. The average temperature of one or more of the sections may be raised to pyrolysis temperatures after production due to mobilization decreases below a selected value. In some embodiments, the average temperature of one or more sections may be raised to pyrolysis temperatures without significant production before reaching pyrolysis temperatures. Formation fluids including pyrolysis products may be produced through the production wells. [0065] In some embodiments, the average temperature of one or more sections may be raised to temperatures sufficient to allow synthesis gas production after mobilization and/or pyrolysis. In some embodiments, hydrocarbons may be raised to temperatures sufficient to allow synthesis gas production without significant production before reaching the temperatures sufficient to allow synthesis gas production. For example, synthesis gas may be produced in a temperature range from about 400 ⁰C to about 1200 ⁰C, about 500 ⁰C to about 1100 ⁰C, or about 550 ⁰C to about 1000 ⁰C. A synthesis gas generating fluid (for example, steam and/or water) may be introduced into the sections to generate synthesis gas. Synthesis gas may be produced from production wells. [0066] Solution mining, removal of volatile hydrocarbons and water, mobilizing hydrocarbons, pyrolyzing hydrocarbons, generating synthesis gas, and/or other processes may be performed during the in situ heat treatment process. In some embodiments, some processes may be performed after the in situ heat treatment process. Such processes may include, but are not limited to, recovering heat from treated sections, storing fluids (for example, water and/or hydrocarbons) in previously treated sections, and/or sequestering carbon dioxide in previously treated sections.

[0067] FIG. 1 depicts a schematic view of an embodiment of a portion of the in situ heat treatment system for treating the hydrocarbon containing formation. The in situ heat treatment system may include barrier wells 200. Barrier wells are used to form a barrier around a treatment area. The barrier inhibits fluid flow into and/or out of the treatment area. Barrier wells include, but are not limited to, dewatering wells, vacuum wells, capture wells, injection wells, grout wells, freeze wells, or combinations thereof. In some embodiments, barrier wells 200 are dewatering wells. Dewatering wells may remove liquid water and/or inhibit liquid water from entering a portion of the formation to be heated, or to the formation being heated. In the embodiment depicted in FIG. 1, the barrier wells 200 are shown extending only along one side of heat sources 202, but the barrier wells typically encircle all heat sources 202 used, or to be used, to heat a treatment area of the formation. [0068] Heat sources 202 are placed in at least a portion of the formation. Heat sources 202 may include heaters such as insulated conductors, conductor-in-conduit heaters, surface burners, flameless distributed combustors, and/or natural distributed combustors. Heat sources 202 may also include other types of heaters. Heat sources 202 provide heat to at least a portion of the formation to heat hydrocarbons in the formation. Energy may be supplied to heat sources 202 through supply lines 204. Supply lines 204 may be structurally different depending on the type of heat source or heat sources used to heat the formation. Supply lines 204 for heat sources may transmit electricity for electric heaters, may transport fuel for combustors, or may transport heat exchange fluid that is circulated in the formation. In some embodiments, electricity for an in situ heat treatment process may be provided by a nuclear power plant or nuclear power plants. The use of nuclear power may allow for reduction or elimination of carbon dioxide emissions from the in situ heat treatment process.

[0069] Heating the formation may cause an increase in permeability and/or porosity of the formation. Increases in permeability and/or porosity may result from a reduction of mass in the formation due to vaporization and removal of water, removal of hydrocarbons, and/or creation of fractures. Fluid may flow more easily in the heated portion of the formation because of the increased permeability and/or porosity of the formation. Fluid in the heated portion of the formation may move a considerable distance through the formation because of the increased permeability and/or porosity. The considerable distance may be over 1000 m depending on various factors, such as permeability of the formation, properties of the fluid, temperature of the formation, and pressure gradient allowing movement of the fluid. The ability of fluid to travel considerable distance in the formation allows production wells 206 to be spaced relatively far apart in the formation. [0070] Production wells 206 are used to remove formation fluid from the formation. In some embodiments, production well 206 includes a heat source. The heat source in the production well may heat one or more portions of the formation at or near the production well. In some in situ heat treatment process embodiments, the amount of heat supplied to the formation from the production well per meter of the production well is less than the amount of heat applied to the formation from a heat source that heats the formation per meter of the heat source. Heat applied to the formation from the production well may increase formation permeability adjacent to the production well by vaporizing and removing liquid phase fluid adjacent to the production well and/or by increasing the permeability of the formation adjacent to the production well by formation of macro and/or micro fractures.

[0071] In some embodiments, the heat source in production well 206 allows for vapor phase removal of formation fluids from the formation. Providing heating at or through the production well may: (1) inhibit condensation and/or re fluxing of production fluid when such production fluid is moving in the production well proximate the overburden, (2) increase heat input into the formation, (3) increase production rate from the production well as compared to a production well without a heat source, (4) inhibit condensation of high carbon number compounds (Ce hydrocarbons and above) in the production well, and/or (5) increase formation permeability at or proximate the production well. [0072] Subsurface pressure in the formation may correspond to the fluid pressure generated in the formation. As temperatures in the heated portion of the formation increase, the pressure in the heated portion may increase as a result of thermal expansion of in situ fluids, increased fluid generation and vaporization of water. Controlling rate of fluid removal from the formation may allow for control of pressure in the formation. Pressure in the formation may be determined at a number of different locations, such as near or at production wells, near or at heat sources, or at monitor wells. [0073] In some hydrocarbon containing formations, production of hydrocarbons from the formation is inhibited until at least some hydrocarbons in the formation have been mobilized and/or pyrolyzed. Formation fluid may be produced from the formation when the formation fluid is of a selected quality. In some embodiments, the selected quality includes an API gravity of at least about 20°, 30°, or 40°. Inhibiting production until at least some hydrocarbons are mobilized and/or pyrolyzed may increase conversion of heavy hydrocarbons to light hydrocarbons. Inhibiting initial production may minimize the production of heavy hydrocarbons from the formation. Production of substantial amounts of heavy hydrocarbons may require expensive equipment and/or reduce the life of production equipment.

[0074] In some embodiments, pressure generated by expansion of mobilized fluids, pyrolysis fluids or other fluids generated in the formation may be allowed to increase although an open path to production wells 206 or any other pressure sink may not yet exist in the formation. The fluid pressure may be allowed to increase towards a lithostatic pressure. Fractures in the hydrocarbon containing formation may form when the fluid approaches the lithostatic pressure. For example, fractures may form from heat sources 202 to production wells 206 in the heated portion of the formation. The generation of fractures in the heated portion may relieve some of the pressure in the portion. Pressure in the formation may have to be maintained below a selected pressure to inhibit unwanted production, fracturing of the overburden or underburden, and/or coking of hydrocarbons in the formation. [0075] After mobilization and/or pyrolysis temperatures are reached and production from the formation is allowed, pressure in the formation may be varied to alter and/or control a composition of formation fluid produced, to control a percentage of condensable fluid as compared to non-condensable fluid in the formation fluid, and/or to control an API gravity of formation fluid being produced. For example, decreasing pressure may result in production of a larger condensable fluid component. The condensable fluid component may contain a larger percentage of olefins.

[0076] In some in situ heat treatment process embodiments, pressure in the formation may be maintained high enough to promote production of formation fluid with an API gravity of greater than 20°. Maintaining increased pressure in the formation may inhibit formation subsidence during in situ heat treatment. Maintaining increased pressure may reduce or eliminate the need to compress formation fluids at the surface to transport the fluids in collection conduits to treatment facilities. [0077] Maintaining increased pressure in a heated portion of the formation may surprisingly allow for production of large quantities of hydrocarbons of increased quality and of relatively low molecular weight. Pressure may be maintained so that formation fluid produced has a minimal amount of compounds above a selected carbon number. The selected carbon number may be at most 25, at most 20, at most 12, or at most 8. Some high carbon number compounds may be entrained in vapor in the formation and may be removed from the formation with the vapor. Maintaining increased pressure in the formation may inhibit entrainment of high carbon number compounds and/or multi-ring hydrocarbon compounds in the vapor. High carbon number compounds and/or multi-ring hydrocarbon compounds may remain in a liquid phase in the formation for significant time periods. The significant time periods may provide sufficient time for the compounds to pyrolyze to form lower carbon number compounds.

[0078] Formation fluid produced from production wells 206 may be transported through collection piping 208 to treatment facilities 210. Formation fluids may also be produced from heat sources 202. For example, fluid may be produced from heat sources 202 to control pressure in the formation adjacent to the heat sources. Fluid produced from heat sources 202 may be transported through tubing or piping to collection piping 208 or the produced fluid may be transported through tubing or piping directly to treatment facilities 210. Treatment facilities 210 may include separation units, reaction units, upgrading units, fuel cells, turbines, storage vessels, and/or other systems and units for processing produced formation fluids. The treatment facilities may form transportation fuel from at least a portion of the hydrocarbons produced from the formation. In some embodiments, the transportation fuel may be jet fuel, such as JP-8.

[0079] In certain embodiments, heaters, heater power sources, production equipment, supply lines, and/or other heater or production support equipment are positioned in tunnels to enable smaller sized heaters and/or smaller sized equipment to be used to treat the formation. Positioning such equipment and/or structures in tunnels may also reduce energy costs for treating the formation, reduce emissions from the treatment process, facilitate heating system installation, and/or reduce heat loss to the overburden as compared to hydrocarbon recovery processes that utilize surface based equipment. The tunnels may be, for example, substantially horizontal tunnels and/or inclined tunnels. U.S. Published Patent Application Nos. 2007/0044957 to Watson et al.; 2008/0017416 to Watson et al.; and 2008/0078552 to Donnelly et al. describe methods of drilling from a shaft for underground recovery of hydrocarbons and methods of underground recovery of hydrocarbons.

[0080] In certain embodiments, tunnels and/or shafts are used in combination with wells to treat the hydrocarbon containing formation using the in situ heat treatment process. FIG. 2 depicts a perspective view of underground treatment system 222. Underground treatment system 222 may be used to treat hydrocarbon layer 216 using the in situ heat treatment process. In certain embodiments, underground treatment system 222 includes shafts 224, utility shafts 226, tunnels 228A, tunnels 228B, and wellbores 212. Tunnels 228A, 228B may be located in overburden 214, an underburden, a non-hydrocarbon containing layer, or a low hydrocarbon content layer of the formation. In some embodiments, tunnels 228A, 228B are located in a rock layer of the formation. In some embodiments, tunnels 228A, 228B are located in an impermeable portion of the formation. For example, tunnels 228A, 228B may be located in a portion of the formation having a permeability of at most about 1 millidarcy.

[0081] Shafts 224 and/or utility shafts 226 may be formed and strengthened (for example, supported to inhibit collapse) using methods known in the art. For example, shafts 224 and/or utility shafts 226 may be formed using blind and raised bore drilling technologies using mud weight and lining to support the shafts. Conventional techniques may be used to raise and lower equipment in the shafts and/or to provide utilities through the shafts. [0082] Tunnels 228A, 228B may be formed and strengthened (for example, supported to inhibit collapse) using methods known in the art. For example, tunnels 228A, 228B may be formed using road-headers, drill and blast, tunnel boring machine, and/or continuous miner technologies to form the tunnels. Tunnel strengthening may be provided by, for example, roof support, mesh, and/or shot-crete. Tunnel strengthening may inhibit tunnel collapse and/or to inhibit movement of the tunnels during heat treatment of the formation. [0083] In certain embodiments, the status of tunnels 228A, tunnels 228B, shafts 224, and/or utility shafts 226 are monitored for changes in structure or integrity of the tunnels or shafts. For example, conventional mine survey technologies may be used to continuously monitor the structure and integrity of the tunnels and/or shafts. In addition, systems may be used to monitor changes in characteristics of the formation that may affect the structure and/or integrity of the tunnels or shafts.

[0084] In certain embodiments, tunnels 228A, 228B are substantially horizontal or inclined in the formation. In some embodiments, tunnels 228A extend along the line of shafts 224 and utility shafts 226. Tunnels 228B may connect between tunnels 228A. In some embodiments, tunnels 228B allow cross-access between tunnels 228A. In some embodiments, tunnels 228B are used to cross-connect production between tunnels 228A below the surface of the formation.

[0085] Tunnels 228A, 228B may have cross-section shapes that are rectangular, circular, elliptical, horseshoe-shaped, irregular-shaped, or combinations thereof. Tunnels 228A, 228B may have cross-sections large enough for personnel, equipment, and/or vehicles to pass through the tunnels. In some embodiments, tunnels 228A, 228B have cross-sections large enough to allow personnel and/or vehicles to freely pass by equipment located in the tunnels. In some embodiments, the tunnels described in the embodiments herein have an average diameter of at least 1 m, at least 2 m, at least 5 m, or at least 10 m. [0086] In certain embodiments, shafts 224 and/or utility shafts 226 connect with tunnels 228A in overburden 214. In some embodiments, shafts 224 and/or utility shafts 226 connect with tunnels 228A in another layer of the formation. Shafts 224 and/or utility shafts 226 may be sunk or formed using methods known in the art for drilling and/or sinking mine shafts. In certain embodiments, shafts 224 and/or utility shafts 226 connect with tunnels 228A in overburden 214 and/or hydrocarbon layer 216 to surface 218. In some embodiments, shafts 224 and/or utility shafts 226 extend into hydrocarbon layer 216. For example, shafts 224 may include production conduits and/or other production equipment to produce fluids from hydrocarbon layer 216 to surface 218. [0087] In certain embodiments, shafts 224 and/or utility shafts 226 are substantially vertical or slightly angled from vertical. In certain embodiments, shafts 224 and/or utility shafts 226 have cross-sections large enough for personnel, equipment, and/or vehicles to pass through the shafts. In some embodiments, shafts 224 and/or utility shafts 226 have circular cross-sections. Shafts and/or utility shafts may have an average cross-sectional diameter of at least 0.5 m, at least 1 m, at least 2 m, at least 5 m, or at least 10 m. [0088] In certain embodiments, the distance between two shafts 224 is between 500 m and 5000 m, between 1000 m and 4000 m, or between 2000 m and 3000 m. In certain embodiments, the distance between two utility shafts 226 is between 100 m and 1000 m, between 250 m and 750 m, or between 400 m and 600 m.

[0089] In certain embodiments, shafts 224 are larger in cross-section than utility shafts 226. Shafts 224 may allow access to tunnels 228A for large ventilation, materials, equipment, vehicles, and personnel. Utility shafts 226 may provide service corridor access to tunnels 228A for equipment or structures such as, but not limited to, power supply legs, production risers, and/or ventilation openings. In some embodiments, shafts 224 and/or utility shafts 226 include monitoring and/or sealing systems to monitor and assess gas levels in the shafts and to seal off the shafts if needed. [0090] FIG. 3 depicts an exploded perspective view of a portion of underground treatment system 222 and tunnels 228A. In certain embodiments, tunnels 228A include heater tunnels 230 and/or utility tunnels 232. In some embodiments, tunnels 228A include additional tunnels such as access tunnels and/or service tunnels. FIG. 4 depicts an exploded perspective view of a portion of underground treatment system 222 and tunnels 228A. Tunnels 228A, as shown in FIG. 4, may include heater tunnels 230, utility tunnels 232, and/or access tunnels 234.

[0091] In certain embodiments, as shown in FIG. 3, wellbores 212 extend from heater tunnels 230. Wellbores 212 may include, but not be limited to, heater wells, heat source wells, production wells, injection wells (for example, steam injection wells), and/or monitoring wells. Heaters and/or heat sources that may be located in wellbores 212 include, but are not limited to, electric heaters, oxidation heaters (gas burners), heaters circulating a heat transfer fluid, closed looped molten salt circulating systems, pulverized coal systems, and/or joule heat sources (heating of the formation using electrical current flow between heat sources having electrically conducting material in two wellbores in the formation). The wellbores used for joule heat sources may extend from the same tunnel (for example, substantially parallel wellbores extending between two tunnels with electrical current flowing between the wellbores) or from different tunnels (for example, wellbores extending from two different tunnels that are spaced to allow electrical current flow between the wellbores). [0092] Heating the formation with heat sources having electrically conducting material may increase permeability in the formation and/or lower viscosity of hydrocarbons in the formation. Heat sources with electrically conducting material may allow current to flow through the formation from one heat source to another heat source. Heating using current flow or "joule heating" through the formation may heat portions of the hydrocarbon layer in a shorter amount of time relative to heating the hydrocarbon layer using conductive heating between heaters spaced apart in the formation.

[0093] In certain embodiments, subsurface formations (for example, tar sands or heavy hydrocarbon formations) include dielectric media. Dielectric media may exhibit conductivity, relative dielectric constant, and loss tangents at temperatures below 100 ⁰C. Loss of conductivity, relative dielectric constant, and dissipation factor may occur as the formation is heated to temperatures above 100 ⁰C due to the loss of moisture contained in the interstitial spaces in the rock matrix of the formation. To prevent loss of moisture, formations may be heated at temperatures and pressures that minimize vaporization of water. In some embodiments, conductive solutions are added to the formation to help maintain the electrical properties of the formation. Heating the formation at low temperatures may require the hydrocarbon layer to be heated for long periods of time to produce permeability and/or injectivity. [0094] In some embodiments, formations are heated using joule heating to temperatures and pressures that vaporize the water and/or conductive solutions. Material used to produce the current flow, however, may become damaged due to heat stress and/or loss of conductive solutions may limit heat transfer in the layer. In addition, when using current flow or joule heating, magnetic fields may form. Due to the presence of magnetic fields, non-ferromagnetic materials may be desired for overburden casings. Although many methods have been described for heating formations using joule heating, efficient and economic methods of heating and producing hydrocarbons using heat sources with electrically conductive material are needed.

[0095] In some embodiments, heat sources that include electrically conductive materials are positioned in the hydrocarbon layer. Electrically resistive portions of the hydrocarbon layer may be heated by electrical current that flows from the heat sources and through the layer. Positioning of electrically conductive heat sources in the hydrocarbon layer at depths sufficient to minimize loss of conductive solutions may allow hydrocarbons layers to be heated at relatively high temperatures over a period of time with minimal loss of water and/or conductive solutions.

[0096] Introduction of heat sources into hydrocarbon layer 216 through heater tunnels 230 allows the hydrocarbon layer to be heated without significant heat losses to overburden 214. Being able to provide heat mainly to hydrocarbon layer 216 with low heat losses in the overburden may enhance heater efficiency. Using tunnels to provide heater sections only in the hydrocarbon layer, and not requiring heater wellbore sections in the overburden, may decrease heater costs by at least 30%, at least 50%, at least 60%, or at least 70% as compared to heater costs using heaters that have sections passing through the overburden.

[0097] In some embodiments, providing heaters through tunnels allows higher heat source densities in the hydrocarbon layer 216 to be obtained. Higher heat source densities may result in faster production of hydrocarbons from the formation. Closer spacing of heaters may be economically beneficial due to a significantly lower cost per additional heater. For example, heaters located in the hydrocarbon layer of a tar sands formation by drilling through the overburden are typically spaced about 12 m apart. Installing heaters from tunnels may allow heaters to be spaced about 8 m apart in the hydrocarbon layer. The closer spacing may accelerate first production to about 2 years as compared to the 5 years for first production obtained from heaters that are spaced 12 m apart and accelerate completion of production to about 5 years from about 8 years. This acceleration in first production may reduce the heating requirement 5% or more.

[0098] In certain embodiments, subsurface connections for heaters or heat sources are made in heater tunnels 230. Connections that are made in heater tunnels 230 include, but are not limited to, insulated electrical connections, physical support connections, and instrumental/diagnostic connections. For example, electrical connection may be made between electric heater elements and bus bars located in heater tunnels 230. The bus bars may be used to provide electrical connection to the ends of the heater elements. In certain embodiments, connections made in heater tunnels 230 are made at a certain safety level. For example, the connections are made such that there is little or no explosion risk (or other potential hazards) in the heater tunnels because of gases from the heat sources or the heat source wellbores that may migrate to heater tunnels 230. In some embodiments, heater tunnels 230 are ventilated to the surface or another area to lower the explosion risk in the heater tunnels. For example, heater tunnels 230 may be vented through utility shafts 226.

[0099] In certain embodiments, heater connections are made between heater tunnels 230 and utility tunnels 232. For example, electrical connections for electric heaters extending from heater tunnels 230 may extend through the heater tunnels into utility tunnels 232. These connections may be substantially sealed such that there is little or no leaking between the tunnels either through or around the connections. [0100] In certain embodiments, utility tunnels 232 include power equipment or other equipment necessary to operate heat sources and/or production equipment. In certain embodiments, transformers 236 and voltage regulators 238 are located in utility tunnels 232. Locating transformers 236 and voltage regulators 238 in the subsurface allows high- voltages to be transported directly into the overburden of the formation to increase the efficiency of providing power to heaters in the formation. [0101] Transformers 236 may be, for example, gas insulated, water cooled transformers such as SF₆ gas-insulated power transformers available from Toshiba Corporation (Tokyo, Japan). Such transformers may be high efficiency transformers. These transformers may be used to provide electricity to multiple heaters in the formation. The higher efficiency of these transformers reduces water cooling requirements for the transformers. Reducing the water cooling requirements of the transformers allows the transformers to be placed in small chambers without the need for extra cooling to keep the transformers from overheating. Water cooling instead of air cooling allows more heat per volume of cooling fluid to be transported to the surface versus air cooling. Using gas-insulated transformers may eliminate the use of flammable oils that may be hazardous in the underground environment. [0102] In some embodiments, voltage regulators 238 are distribution type voltage regulators to control the voltage distributed to heat sources in the tunnels. In some embodiments, transformers 236 are used with load tap changers to control the voltage distributed to heat sources in the tunnels. In some embodiments, variable voltage, load tap changing transformers located in utility tunnels 232 are used to distribute electrical power to, and control the voltage of, heat sources in the tunnels. Transformers 236, voltage regulators 238, load tap changers, and/or variable voltage, load tap changing transformers may control the voltage distributed to either groups or banks of heat sources in the tunnels or individual heat sources. Controlling the voltage distributed to a group of heat sources provides block control for the group of heat sources. Controlling the voltage distributed to individual heat sources provides individual heat source control.

[0103] In some embodiments, transformers 236 and/or voltage regulators 238 are located in side chambers of utility tunnels 232. Locating transformers 236 and/or voltage regulators 238 in side chambers moves the transformers and/or voltage regulators out of the way of personnel, equipment, and/or vehicles moving through utility tunnels 232. Supply lines (for example, supply lines 204 depicted in FIG. 10) in utility shaft 226 may supply power to voltage regulators 238 and transformers 236 in utility tunnels 232. [0104] In some embodiments, such as shown in FIG. 3, voltage regulators 238 are located in power chambers 240. Power chambers 240 may connect to utility tunnels 232 or be side chambers of the utility tunnels. Power may be brought into power chambers 240 through utility shafts 226. Use of power chambers 240 may allow easier, quicker, and/or more effective maintenance, repair, and/or replacement of the connections made to heat sources in the subsurface. [0105] In certain embodiments, sections of heater tunnels 230 and utility tunnels 232 are interconnected by connecting tunnels 248. Connecting tunnels 248 may allow access between heater tunnels 230 and utility tunnels 232. Connecting tunnels 248 may include airlocks or other structures to provide a seal that can be opened and closed between heater tunnels 230 and utility tunnels 232. [0106] In some embodiments, heater tunnels 230 include pipelines 208 or other conduits. In some embodiments, pipelines 208 are used to produce fluids (for example, formation fluids such as hydrocarbon fluids) from production wells or heater wells coupled to heater tunnels 230. In some embodiments, pipelines 208 are used to provide fluids used in production wells or heater wells (for example, heat transfer fluids for circulating fluid heaters or gas for gas burners). Pumps and associated equipment 252 for pipelines 208 may be located in pipeline chambers 254 or other side chambers of the tunnels. In some embodiments, pipeline chambers 254 are isolated (sealed off) from heater tunnels 232. Fluids may be provided to and/or removed from pipeline chambers 254 using risers and/or pumps located in utility shafts 226. [0107] In some embodiments, heat sources are used in wellbores 212 proximate heater tunnels 230 to control viscosity of formation fluids being produced from the formation. The heat sources may have various lengths and/or provide different amounts of heat at different locations in the formation. In some embodiments, the heat sources are located in wellbores 212 used for producing fluids from the formation (for example, production wells).

[0108] As shown in FIG. 2, wellbores 212 may extend between tunnels 228A in hydrocarbon layer 216. Tunnels 228A may include one or more of heater tunnels 230, utility tunnels 232, and/or access tunnels 234. In some embodiments, access tunnels 234 are used as ventilation tunnels. It should be understood that the any number of tunnels and/or any order of tunnels may be used as contemplated or desired. [0109] In some embodiments, heated fluid may flow through wellbores 212 or heat sources that extend between tunnels 228A. For example, heated fluid may flow between a first heater tunnel and a second heater tunnel. The second tunnel may include a production system that is capable of removing the heated fluids from the formation to the surface of the formation. In some embodiments, the second tunnel includes equipment that collects heated fluids from at least two wellbores. In some embodiments, the heated fluids are moved to the surface using a lift system. The lift system may be located in utility shaft 226 or a separate production wellbore.

[0110] Production well lift systems may be used to efficiently transport formation fluid from the bottom of the production wells to the surface. Production well lift systems may provide and maintain the maximum required well drawdown (minimum reservoir producing pressure) and producing rates. The production well lift systems may operate efficiently over a wide range of high temperature/multiphase fluids

(gas/vapor/steam/water/hydrocarbon liquids) and production rates expected during the life of a typical project. Production well lift systems may include dual concentric rod pump lift systems, chamber lift systems and other types of lift systems. [0111] FIG. 5 depicts a side view representation of an embodiment for flowing heated fluid in heat sources 202 between tunnels 228A. FIG. 6 depicts a top view representation of the embodiment depicted in FIG. 5. Circulation system 220 may circulate heated fluid (for example, molten salt) through heat sources 202. Shafts 226 and tunnels 228A may be used to provide the heated fluid to the heat sources and return the heated fluid from the heat sources. Large diameter piping may be used in shafts 226 and tunnels 228A. Large diameter piping may minimize pressure drops in transporting the heated fluid through the overburden of the formation. Piping in shafts 226 and tunnels 228A may be insulated to inhibit heat losses in the overburden. [0112] FIG. 7 depicts another perspective view of an embodiment of underground treatment system 222 with wellbores 212 extending between tunnels 228A. Heat sources or heaters may be located in wellbores 212. In certain embodiments, wellbores 212 extend from wellbore chambers 256. Wellbore chambers 256 may be connected to the sides of tunnels 228A or be side chambers of the tunnels.

[0113] FIG. 8 depicts a top view of an embodiment of tunnel 228A with wellbore chambers 256. In certain embodiments, power chambers 240 are connected to utility tunnel 232. Transformers 236 and/or other power equipment may be located in power chambers 240. [0114] In certain embodiments, tunnel 228A includes heater tunnel 230 and utility tunnel 232. Heater tunnel 230 may be connected to utility tunnel 232 with connecting tunnel 248. Wellbore chambers 256 are connected to heater tunnel 230. In certain embodiments, wellbore chambers 256 include heater wellbore chambers 256A and adjunct wellbore chambers 256B. Heat sources 202 (for example, heaters) may extend from heater wellbore chambers 256A. Heat sources 202 may be located in wellbores extending from heater wellbore chambers 256A.

[0115] In certain embodiments, heater wellbore chambers 256A have angled side walls with respect to heater tunnel 230 to allow heat sources to be installed into the chambers more easily. The heaters may have limited bending capability and the angled walls may allow the heaters to be installed into the chambers without overbending the heaters.

[0116] In certain embodiments, barrier 258 seals off heater wellbore chambers 256A from heater tunnel 230. Barrier 258 may be a fire and/or blast resistant barrier (for example, a concrete wall). In some embodiments, barrier 258 includes an access port (for example, an access door) to allow entry into the chambers. In some embodiments, heater wellbore chambers 256A are sealed off from heater tunnel 230 after heat sources 202 have been installed. Utility shaft 226 may provide ventilation into heater wellbore chambers 256A. In some embodiments, utility shaft 226 is used to provide a fire or blast suppression fluid into heater wellbore chambers 256A. [0117] In certain embodiments, adjunct wellbores 212A extend from adjunct wellbore chambers 256B. Adjunct wellbores 212A may include wellbores used as, for example, infill wellbores (repair wellbores) or intervention wellbores for killing leaks and/or monitoring wellbores. Barrier 258 may seal off adjunct wellbore chambers 256B from heater tunnel 230. In some embodiments, heater wellbore chambers 256A and/or adjunct wellbore chambers 256B are cemented in (the chambers are filled with cement). Filling the chambers with cement substantially seals off the chambers from inflow or outflow of fluids.

[0118] As shown in FIGS. 2 and 7, wellbores 212 may be formed between tunnels 228A. Wellbores 212 may be formed substantially vertically, substantially horizontally, or inclined in hydrocarbon layer 216 by drilling into the hydrocarbon layer from tunnels 228A. Wellbores 212 may be formed using drilling techniques known in the art. For example, wellbores 212 may be formed by pneumatic drilling using coiled tubing available from Penguin Automated Systems (Naughton, Ontario, Canada). [0119] Drilling wellbores 212 from tunnels 228A may increase drilling efficiency and decrease drilling time and allow for longer wellbores because the wellbores do not have to be drilled through overburden 214. Tunnels 228A may allow large surface footprint equipment to be placed in the subsurface instead of at the surface. Drilling from tunnels 228A and subsequent placement of equipment and/or connections in the tunnels may reduce a surface footprint as compared to conventional surface drilling methods that use surface based equipment and connections.

[0120] Using shafts and tunnels in combination with the in situ heat treatment process for treating the hydrocarbon containing formation may be beneficial because the overburden section is eliminated from wellbore construction, heater construction, and/or drilling requirements. In some embodiments, at least a portion of the shafts and tunnels are located below aquifers in or above the hydrocarbon containing formation. Locating the shafts and tunnels below the aquifers may reduce contamination risk to the aquifers, and/or may simplify abandonment of the shafts and tunnels after treatment of the formation. [0121] In certain embodiments, underground treatment system 222 (depicted in FIGS. 2, 3, 7, 11, and 10) includes one or more seals to seal the tunnels and shafts from the formation pressure and formation fluids. For example, the underground treatment system may include one or more impermeable barriers to seal personnel workspace from the formation. In some embodiments, wellbores are sealed off with impermeable barriers to the tunnels and shafts to inhibit fluids from entering the tunnels and shafts from the wellbores. In some embodiments, the impermeable barriers include cement or other packing materials. In some embodiments, the seals include valves or valve systems, airlocks, or other sealing systems known in the art. The underground treatment system may include at least one entry/exit point to the surface for access by personnel, vehicles, and/or equipment. [0122] FIG. 9 depicts a top view of an embodiment of development of tunnel 228A. Heater tunnel 230 may include heat source section 242, connecting section 244, and/or drilling section 246 as the heater tunnel is being formed left to right. From heat source section 242, wellbores 212 have been formed and heat sources have been introduced into the wellbores. In some embodiments, heat source section 242 is considered a hazardous confined space. Heat source section 242 may be isolated from other sections in heater tunnel 230 and/or utility tunnel 232 with material impermeable to hydrocarbon gases and/or hydrogen sulfide. For example, cement or another impermeable material may be used to seal off heat source section 242 from heater tunnel 230 and/or utility tunnel 232. In some embodiments, impermeable material is used to seal off heat source section 242 from the heated portion of the formation to inhibit formation fluids or other hazardous fluids from entering the heat source section. In some embodiments, at least 30 m, at least 40 m, or at least 50 m of wellbore is between the heat sources and heater tunnel 230. In some embodiments, shaft 224 proximate to heater tunnel 230 is sealed (for example, filled with cement) after heating has been initiated in the hydrocarbon layer to inhibit gas or other fluids from entering the shaft.

[0123] In some embodiments, heaters controls may be located in utility tunnel 232. In some embodiments, utility tunnel 232 includes electrical connections, combustors, tanks, and/or pumps necessary to support heaters and/or heat transport systems. For example, transformers 236 may be located in utility tunnel 232.

[0124] Connecting section 244 may be located after heat source section 242. Connecting section 244 may include space for performing operations necessary for installing the heat sources and/or connecting heat sources (for example, making electrical connections to the heaters). In some embodiments, connections and/or movement of equipment in connecting section 244 is automated using robotics or other automation techniques. Drilling section 246 may be located after connecting section 244. Additional wellbores may be dug and/or the tunnel may be extended in drilling section 246.

[0125] In certain embodiments, operations in heat source section 242, connecting section 244, and/or drilling section 246 are independent of each other. Heat source section 242, connecting section 244, and/or production section 246 may have dedicated ventilation systems and/or connections to utility tunnel 232. Connecting tunnels 248 may allow access and egress to heat source section 242, connecting section 244, and/or drilling section 246. [0126] In certain embodiments, connecting tunnels 248 include airlocks 250 and/or other barriers. Airlocks 250 may help regulate the relative pressures such that the pressure in heat source section 242 is less than the air pressure in connecting section 244, which is less than the air pressure in drilling section 246. Air flow may move into heat source section 242 (the most hazardous area) to reduce the probability of a flammable atmosphere in utility tunnel 232, connecting section 244, and/or drilling section 246. Airlocks 250 may include suitable gas detection and alarms to ensure transformers or other electrical equipment are de-energized in the event that an unsafe flammable limit is encountered in the utility tunnel 232 (for example, less than one-half of the lower flammable limit). Automated controls may be used to operate airlocks 250 and/or the other barriers. Airlocks 250 may be operated to allow personnel controlled access and/or egress during normal operations and/or emergency situations.

[0127] In certain embodiments, heat sources located in wellbores extending from tunnels are used to heat the hydrocarbon layer. The heat from the heat sources may mobilize hydrocarbons in the hydrocarbon layer and the mobilized hydrocarbons flow towards production wells. Production wells may be positioned in the hydrocarbon layer below, adjacent, or above the heat sources to produce the mobilized fluids. In some embodiments, formation fluids may gravity drain into tunnels located in the hydrocarbon layer. Production systems may be installed in the tunnels (for example, pipeline 208 depicted in FIG. 3). The tunnel production systems may be operated from surface facilities and/or facilities in the tunnel. Piping, holding facilities, and/or production wells may be located in a production portion of the tunnels to be used to produce the fluids from the tunnels. The production portion of the tunnels may be sealed with an impervious material (for example, cement or a steel liner). The formation fluids may be pumped to the surface through a riser and/or vertical production well located in the tunnels. In some embodiments, formation fluids from multiple horizontal production wellbores drain into one vertical production well located in one tunnel. The formation fluids may be produced to the surface through the vertical production well. [0128] In some embodiments, a production wellbore extending directly from the surface to the hydrocarbon layer is used to produce fluids from the hydrocarbon layer. FIG. 10 depicts production well 206 extending from the surface into hydrocarbon layer 216. In certain embodiments, production well 206 is substantially horizontally located in hydrocarbon layer 216. Production well 206 may, however, have any orientation desired. For example, production well 206 may be a substantially vertical production well. [0129] In some embodiments, as shown in FIG. 10, production well 206 extends from the surface of the formation and heat sources 202 extend from tunnels 228A in overburden 214 or another impermeable layer of the formation. Having the production well separated from the tunnels used to provide heat sources into the formation may reduce risks associated with having hot formation fluids (for example, hot hydrocarbon fluids) in the tunnels and near electrical equipment or other heater equipment. In some embodiments, the distance between the location of production wells on the surface and the location of fluid intakes, ventilation intakes, and/or other possible intakes into the tunnels below the surface is maximized to minimize the risk of fluids reentering the formation through the intakes. [0130] In some embodiments, wellbores 212 interconnect with utility tunnels 232 or other tunnels below the overburden of the formation. FIG. 11 depicts a side view of an embodiment of underground treatment system 222. In certain embodiments, wellbores 212 are directionally drilled to utility tunnels 232 in hydrocarbon layer 216. Wellbores 212 may be directional drilled from the surface or from tunnels located in overburden 214. Directional drilling to intersect utility tunnel 232 in hydrocarbon layer 216 may be easier than directional drilling to intersect another wellbore in the formation. Drilling equipment such as, but not limited to, magnetic transmission equipment, magnetic sensing equipment, acoustic transmission equipment, and acoustic sensing equipment may be located in utility tunnels 232 and used for directional drilling of wellbores 212. The drilling equipment may be removed from utility tunnels 232 after directional drilling is completed. In some embodiments, utility tunnels 232 are later used for collection and/or production of fluids from the formation during the in situ heat treatment process. [0131] Further modifications and alternative embodiments of various aspects of the invention may be apparent to those skilled in the art in view of this description. Accordingly, this description is to be construed as illustrative only and is for the purpose of teaching those skilled in the art the general manner of carrying out the invention. It is to be understood that the forms of the invention shown and described herein are to be taken as the presently preferred embodiments. Elements and materials may be substituted for those illustrated and described herein, parts and processes may be reversed, and certain features of the invention may be utilized independently, all as would be apparent to one skilled in the art after having the benefit of this description of the invention. Changes may be made in the elements described herein without departing from the spirit and scope of the invention as described in the following claims. In addition, it is to be understood that features described herein independently may, in certain embodiments, be combined.

Claims

C L A I M S

I . A system for treating a subsurface hydrocarbon containing formation, comprising: one or more tunnels, the tunnels having an average diameter of at least 1 m, at least one tunnel being connected to the surface; and two or more wellbores extending from at least one of the tunnels into at least a portion of the subsurface hydrocarbon containing formation, at least two of the wellbores containing elongated heat sources configured to heat at least a portion of the subsurface hydrocarbon containing formation such that at least some hydrocarbons are mobilized.

2. The system of claim 1, further comprising at least one shaft connecting at least one of the tunnels to the surface.

3. The system of claim 1, further comprising at least one shaft connecting at least one of the tunnels to the surface, wherein at least one shaft is substantially vertically oriented.

4. The system of claim 1, further comprising a production well located such that mobilized fluids from the formation drain into the production well.

5. The system of claim 1, further comprising a production system located in at least one of the tunnels, the production system being configured to produce fluids from the formation that collect in the tunnel.

6. The system of claim 5, wherein the production system tunnel is located to collect fluids in the formation by gravity drainage.

7. The system of claim 5, wherein the production system comprises a substantially vertical production wellbore coupled to the production system tunnel.

8. The system of claim 1, further comprising at least one steam injection wellbore extending from at least one tunnel, the steam injection wellbore being connected to one or more sources of steam, and at least one of the steam injection wellbores being configured to provide steam to the subsurface hydrocarbon containing formation.

9. The system of claim 1, wherein at least one of the tunnels has an average diameter of at least 2 m.

10. The system of claim 1, wherein the cross-sectional shape of at least one tunnel is circular, oval, orthogonal, or irregular shaped.

I I. The system of claim 1, wherein at least one of the heat sources is an electric resistance heater, and a conductor located in at least one tunnel is configured to provide electrical power to the heater.

12. The system of claim 1, wherein at least one of the heat sources is a gas burner, and further comprising a conduit configured to carry fuel gas for the gas burner, wherein the conduit is located in at least one tunnel.

13. The system of claim 1, wherein at least two of the heat sources are configured to allow at least some flow of electrical current between the heat sources to heat the formation.

14. The system of claim 13, wherein the electrical current flow between the heat sources is configured to resistively heat the formation.

15. The system of claim 1, wherein at least two of the wellbores are configured to allow heated fluid to flow between at least two tunnels to heat the formation.

16. The system of claim 15, further comprising a production system coupled to at least one of the tunnels, the production system being configured to remove the heated fluids from the formation to the surface of the formation.

17. The system of claim 16, wherein the production system comprises a lift system to move the heated fluids to the surface of the formation.

18. The system of claim 1, wherein at least one of the tunnels is substantially horizontal, and at least two of the wellbores extend at an angle from the tunnel.

19. The system of claim 1, further comprising one or more impermeable barriers in the tunnels configured to seal the tunnels from formation fluids.

20. The system of claim 1, wherein at least one of the wellbores is directionally drilled between at least two of the tunnels.

21. A method of treating a subsurface hydrocarbon containing formation, comprising: providing heat from the system to the subsurface hydrocarbon containing formation to mobilize at least some of the hydrocarbons in the formation, the heat being provided by the system of any one of claims 1-20.

22. The method of claim 21, further comprising producing formation fluids from the portion.

23. The method of claim 21, further comprising allowing formation fluids to drain to at least one of the tunnels, and producing fluids from the drainage tunnel to the surface of the formation using a production system.